Production from most oil wells takes the form of a multiconstituent flowstream. For a typical oil well this flowstream includes crude oil, brine, hydrocarbon gases, various inorganic gases, and minor amounts of particulate matter. The fractional representation of each constituent of the production flowstream varies from well to well, and even for a single well can vary significantly over time. It is often necessary to maintain data on the rate at which each of the flowstream constituents is produced for one or more wells in a reservoir. This information is useful in monitoring the effectiveness of the reservoir production scheme, detecting faults in the production equipment for an individual well, adjusting the equipment used for separating the produced fluids collected from groups of wells, and in determining royalty payments for produced hydrocarbons.
The earliest methods for determining the fractional representation of the various fluids within the flowstream of an oil well relied on manual sampling and analytical procedures. A representative sample of the flowstream was collected and through physical separation and chemical analysis the fractional representation of each constituent was determined. Manual analysis is still used today in many instances, particularly where accuracy is particularly important. However, manual testing is relatively expensive, particularly in remote oil fields or where frequent updating is necessary. Further, collecting small volume samples which accurately represent the flowstream is difficult, especially in high pressure, high temperature production systems.
Automated flowstream analysis systems have been developed to avoid much of the expense associated with manual testing. These automated systems typically rely on gravity driven physical separation of the constituents of the flowstream. Such systems are not accurate for applications where the flowstream includes an oil-water emulsion, which cannot be gravity separated. Such systems are also of limited use for heavy oil reservoirs, where the density difference between the produced oil and brine is too small to provide significant driving force for gravity separation. Gravity driven automated analysis systems also tend to be bulky, expensive, and require careful maintenance.
To avoid many of the disadvantages of traditional methods of flowstream analysis, monitoring systems have been developed which are based on interactions between the flowstream and a population of neutrons introduced into the flowstream. The general principle of operation of neutron type monitoring systems is that by detecting the frequency with which characteristic neutron-nuclide reactions occur, the relative abundance of various elements within the flowstream can be determined. From this data it is possible, knowing the elemental composition of the various constituents of the flowstream, to derive the fractional representation of each constituent of the flowstream. Since neutrons and the gamma radiation resulting from the interaction of neutrons with matter are only slightly attenuated in passing through a metallic conduit, the neutron source and the various detectors can be positioned external to the conduit. This avoids the need to withdraw a representative sample of the flowstream or position a monitor in physical contact with the flowstream, as is necessary in other methods of analysis.
Though neutron type monitoring systems provide significant advantages over traditional methods of flowstream analysis, the various neutron type monitoring systems developed heretofore are subject to limitations which greatly restrict their use in oil field applications. These limitations are best appreciated by considering the principles of operation of two classes of neutron monitoring systems familiar to those skilled in the art.
One class of neutron based flowstream monitors is illustrated by U.S. Pat. No. 4,190,768, issued Feb. 26, 1980. An oil, gas and water mixture within a pipeline is exposed to a neutron population. The neutrons are moderated (thermalized) by the hydrogen and carbon nuclides within the fluid. A portion of the thermal neutrons are captured by the constituent nuclides of the fluid. Each neutron capture event results in the emission of a prompt gamma photon having an energy characteristic of the nuclide. By monitoring the gamma ray emissions characteristic of the reactions H.sup.1 (n,.gamma.)H.sup.2, S.sup.32 (n,.gamma.)S.sup.33, and Cl.sup.35 (n,.gamma.)Cl.sup.36 the fractional amounts of crude oil, water and gas within the fluid can be determined. This method is disadvantageous in that it is dependent upon a precise knowledge of the concentration of sulphur within the oil for quantifying the amount of crude oil present. This requires a continuous, separate chemical analysis. Further, because the method relies on thermal neutron capture, it requires that the source neutrons be moderated. Where the conduit contains a significant quantity of hydrogenous fluid this does not pose a problem. However, where the conduit is small or the fluid is predominantly gas, supplemental moderation must be provided.
An alternate neutron based fluid monitoring system is set forth in U.S. Pat. No. 2,567,057, issued Sept. 4, 1951. In this system a collimated beam of fast or epithermal neutrons is directed into a conduit. A neutron detector is positioned to monitor the degree of attenuation of the neutron flux resulting from neutron capture or scattering. The fractional decrease in the flux can be related to the composition of the sample. This system is useful in measuring changes in the composition of simple non-gaseous fluid, but is not useful where a significant amount of gas is present in the sample. Additionally, the accuracy of this method diminishes significantly at sample thicknesses greater than one or two centimeters. This precludes use of this system "in-situ" in oil field applications, where production conduits have inside diameters generally well in excess of 5 cm. This system is further disadvantageous in that it cannot distinguish between oil and water.
It would be desirable to develop a neutron based monitoring system which could be used in conjunction with unmodified production equipment to determine the composition of oil field production flowstreams. It would be further desirable if this system does not rely on the detection of trace impurities for distinguishing between oil and water and can be used to accurately monitor fluids over a wide range of gas, water, and oil fractions.